UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

For the quarterly period ended September 30, 2015

OR

For the transition period from                      to                     

 

 

 

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.     YES  x    NO  ¨

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).     YES  x    NO  ¨

Indicate by check mark whether TECO Energy, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Indicate by check mark whether Tampa Electric Company is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Indicate by check mark whether TECO Energy, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act).     YES  ¨    NO  x

Indicate by check mark whether Tampa Electric Company is a shell company (as defined in Rule 12b-2 of the Exchange Act).     YES  ¨    NO  x

The number of shares of TECO Energy, Inc.’s common stock outstanding as of October 31, 2015 was 235,230,760. As of October 31, 2015, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

Tampa Electric Company meets the conditions set forth in General Instruction (H) (1) (a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format.

This combined Form 10-Q represents separate filings by TECO Energy, Inc. and Tampa Electric Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Each registrant makes representations only as to information relating to itself and its subsidiaries.

 

 

 

 

 

 

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DEFINITIONS

Acronyms and defined terms used in this and other filings with the U.S. Securities and Exchange Commission include the following:

 

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PART I. FINANCIAL INFORMATION

 

Item 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

 

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TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

 

 

The accompanying notes are an integral part of the consolidated condensed financial statements.

 

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 TECO ENERGY, INC.

Consolidated Condensed Balance Sheets - continued

Unaudited

 

 

The accompanying notes are an integral part of the consolidated condensed financial statements.

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TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

 

 

The accompanying notes are an integral part of the consolidated condensed financial statements.

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TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

 

 

The accompanying notes are an integral part of the consolidated condensed financial statements.

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TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

 

 

The accompanying notes are an integral part of the consolidated condensed financial statements.

 

 

 

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TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

 

 

The accompanying notes are an integral part of the consolidated condensed financial statements.

 

 

 

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TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

 

1. Summary of Significant Accounting Policies

See TECO Energy, Inc.’s 2014 Annual Report on Form 10-K for a complete discussion of accounting policies. The significant accounting policies for all utility and diversified operations include:

Principles of Consolidation and Basis of Presentation

Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of Sept. 30, 2015 and Dec. 31, 2014, and the results of operations and cash flows for the periods ended Sept. 30, 2015 and 2014. The results of operations for the three and nine months ended Sept. 30, 2015 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2015.

The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. The year-end consolidated condensed balance sheet data was derived from audited financial statements; however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP.

The consolidated financial statements include NMGI and NMGC from the acquisition date of Sept. 2, 2014 through Sept. 30, 2015. In addition, all periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges and gains at Parent and TECO Diversified that directly related to TECO Coal and TECO Guatemala (see Note 15).

On Sept. 4, 2015, TECO Energy and Emera entered into an agreement and plan of merger (Merger Agreement). Upon closing, TECO Energy will become a wholly owned subsidiary of Emera. See Note 16 for further information.

Revenues

As of Sept. 30, 2015 and Dec. 31, 2014, unbilled revenues of $66.7 million and $86.6 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipt Taxes

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $31.7 million and $88.3 million, respectively, for the three and nine months ended Sept. 30, 2015, compared to $31.7 million and $86.7 million, respectively, for the three and nine months ended Sept. 30, 2014.

NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line-item impact on the Consolidated Condensed Statements of Income.

 

2. New Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This guidance will be effective for the company beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The company is currently evaluating the impact of the adoption of this guidance on its financial statements but does not expect the impact to be significant.

Presentation of Debt Issuance Costs

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as

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an asset, regardless of whether a balance is outstanding. This guidance will be effective for the company beginning in 2016 and will be required to be applied on a retrospective basis for all periods presented. As of Sept. 30, 2015, $29.0 million of debt issuance costs, which does not include costs for line-of-credit arrangements, are included in the “Deferred charges and other assets” line item on the company’s Consolidated Condensed Balance Sheet.

 

Disclosure of Investments Using Net Asset Value

In May 2015, the FASB issued guidance stating that investments for which fair value is measured using the NAV per share practical expedient should not be categorized in the fair value hierarchy but should be provided to reconcile to total investments on the balance sheet. In addition, the guidance clarifies that a plan sponsor’s pension assets are eligible to be measured at NAV as a practical expedient and that those investments should also not be categorized in the fair value hierarchy. TECO Energy’s pension plan has such investments as disclosed in Note 5 of its 2014 Annual Report on Form 10-K. This standard will be effective for the company beginning in 2016 and will be required to be applied on a retrospective basis for all periods presented. The company is considering adopting the standard for its 2015 fiscal year, as early adoption is permitted.

Measurement Period Adjustments in Business Combinations

In September 2015, the FASB issued guidance requiring an acquirer in a business combination to account for measurement period adjustments during the reporting period in which the adjustment is determined, rather than retrospectively. When measurements are incomplete as of the end of the reporting period covering a business combination, an acquirer may record adjustments to provisional amounts based on events and circumstances that existed as of the acquisition date during the period from the date of acquisition to the date information is received, not to exceed one year. The guidance will be effective for the company beginning in 2016 and will be applied prospectively. The company will assess the potential impact of the guidance on future transactions.

 

3. Regulatory

Tampa Electric’s retail business and PGS are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

NMGC is subject to regulation by the NMPRC. The NMPRC has jurisdiction over the regulatory matters related, directly and indirectly, to NMGC providing service to its customers, including, among other things, rates, accounting procedures, securities issuances, and standards of service. NMGC must follow certain accounting guidance that pertains specifically to entities that are subject to such regulation. Comparable to the FPSC, the NMPRC sets rates at a level that allows utilities such as NMGC to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

 

Regulatory Assets and Liabilities

Tampa Electric, PGS and NMGC apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process.

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Details of the regulatory assets and liabilities as of Sept. 30, 2015 and Dec. 31, 2014 are presented in the following table:

 

 

 

4. Income Taxes

The effective tax rate increased to 39.10% for the nine months ended Sept. 30, 2015 from 35.38% for the same period in 2014 primarily due to higher state taxes and tax expense related to long-term incentive compensation shares that vested below target levels. The nine months ended Sept. 30, 2014 included a favorable state tax adjustment related to the acquisition of NMGC.

The company’s subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2013 consolidated federal income tax return in January 2015. The U.S. federal statute of limitations remains open for the year 2012 and forward. Years 2014 and 2015 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2015. U.S. state jurisdictions have statutes of limitations generally ranging from three to four years from the filing of an income tax return. Additionally, any state net operating losses that were generated in prior years and are still being utilized are subject to examination by state jurisdictions. The state impact of any federal changes remains subject to

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examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by taxing authorities in major state jurisdictions and foreign jurisdictions include 2005 and forward.

 

 

5. Employee Postretirement Benefits

Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company. Amounts disclosed for pension benefits include the amounts related to the qualified pension plan and the non-qualified, non-contributory SERP.

 

For the fiscal 2015 plan year, TECO Energy is using an assumed long-term EROA of 7.00% and a discount rate of 4.256% for pension benefits under its qualified pension plan. For the Jan. 1, 2015 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 4.206% for the Florida-based plan and 4.243% for the NMGC plan.

TECO Energy made contributions of $55.0 million and $47.5 million to its pension plan for the nine months ended Sept. 30, 2015 and 2014, respectively. Additionally, NMGC made contributions of $2.7 million to its other postretirement benefits plan for the nine months ended Sept. 30, 2015. In addition, in October 2015, TECO Energy made a contribution of $43.4 million to the SERP’s trust in order to fully fund its SERP obligation following the signing of the Merger Agreement with Emera. The execution of the Merger Agreement constituted a potential change in control under the trust; therefore, TECO Energy is required to maintain such funding as of the end of each calendar year, including 2015. The fully funded amount is equal to the aggregate present value of all benefits then in pay status under the SERP plus all benefits that would become payable under the SERP to current participants.

For the three and nine months ended Sept. 30, 2015, TECO Energy and its subsidiaries reclassified $0.2 million and $2.4 million, respectively, of pretax unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense, compared with $0.7 million and $2.0 million for the three and nine months ended Sept. 30, 2014, respectively. In addition, during the three and nine months ended Sept. 30, 2015, the regulated companies reclassified $2.6 million and $7.8 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense, compared with $2.7 million and $7.9 million during the three and nine months ended Sept. 30, 2014, respectively.

 

Black Lung Liability

As discussed in Note 15, TECO Diversified completed the sale of all of its ownership interest in TECO Coal to Cambrian Coal Corporation on Sept. 21, 2015. TECO Coal was required by federal and state statutes to provide benefits to terminated, retired or

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(under state statutes) qualifying active employees for benefits related to black lung disease. TECO Coal was self-insured for black lung related claims. TECO Coal applied the accounting guidance of ASC 715, Compensation – Retirement Benefits, and annual expense was recorded for black lung obligations as determined by an independent actuary at the present value of the actuarially-computed liability for such benefits over the employee’s applicable term of service. Expense related to the black lung liability recognized during the three and nine months ended Sept. 30, 2015 and 2014 was not material.

In accordance with ASC 715, an after-tax settlement charge of $7.7 million related to the unfunded black lung obligations recorded in AOCI was recognized as a loss from discontinued operations upon completion of the sale of TECO Coal.

 

 

6. Short-Term Debt

At Sept. 30, 2015 and Dec. 31, 2014, the following credit facilities and related borrowings existed:

 

 

At Sept. 30, 2015, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Sept. 30, 2015 and Dec. 31, 2014 was 1.28% and 1.16%, respectively.  

Tampa Electric Company Accounts Receivable Facility

On Mar. 24, 2015, TEC and TRC amended and restated their $150 million accounts receivable collateralized borrowing facility in order to (i) appoint The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (BTMU), as Program Agent, replacing the previous Program Agent, Citibank, N.A., (ii) add new lenders, and (iii) extend the scheduled termination date from Apr. 14, 2015 to Mar. 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement dated as of Mar. 24, 2015 between TEC and TRC and (b) a Loan and Servicing Agreement dated as of Mar. 24, 2015, among TEC as Servicer, TRC as Borrower, certain lenders named therein and BTMU, as Program Agent (the Loan Agreement). Under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding in the case of default. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of Sept. 30, 2015, TEC and TRC were in compliance with the requirements of the agreement.

 

7. Long-Term Debt

Fair Value of Long-Term Debt

At Sept. 30, 2015, total long-term debt had a carrying amount of $3,851.0 million and an estimated fair market value of $4,126.1 million. At Dec. 31, 2014, total long-term debt had a carrying amount of $3,628.5 million and an estimated fair market value of $3,987.8 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments (see Note 13 for information regarding the fair value hierarchy).  

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Issuance of TEC 4.20% Notes due 2045

On May 20, 2015, TEC completed an offering of $250 million aggregate principal amount of 4.20% Notes due May 15, 2045 (the Notes).  The Notes were sold at 99.814% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $246.8 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Until Nov. 15, 2044, TEC may redeem all or any part of the Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.  At any time on or after Nov. 15, 2044, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

 

Issuance of TECO Finance Floating Rate Notes due 2018

On Apr. 10, 2015, TECO Finance completed an offering of $250 million aggregate principal amount of floating rate notes due 2018 (the 2018 Notes), which are guaranteed by TECO Energy. The 2018 Notes were sold at par and mature on Apr. 10, 2018, The 2018 Notes will bear interest at a floating rate that is reset quarterly based on the three-month LIBOR plus 60 basis points, which is payable quarterly on Jan. 10, Apr. 10, July 10 and Oct. 10 of each year, beginning July 10, 2015. Interest on the 2018 Notes will be computed on the basis of the actual number of days elapsed over a 360-day year. The 2018 Notes will not be subject to redemption prior to maturity. The 2018 Notes are effectively subordinated to existing and future liabilities of TECO Energy’s subsidiaries to their respective creditors, and also are effectively subordinated to any secured debt that TECO Finance and TECO Energy incur to the extent of the value of the assets securing that indebtedness. TECO Finance is a wholly owned subsidiary of TECO Energy whose business activities consist solely of providing funds to TECO Energy.

The offering resulted in net proceeds to TECO Finance (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $248.6 million. TECO Finance used these net proceeds to repay borrowings under the TECO Finance credit facility and to fund a portion of the payment at maturity of $191 million of TECO Finance notes due in May 2015.  

 

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8. Other Comprehensive Income

TECO Energy reported the following OCI for the three and nine months ended Sept. 30, 2015 and 2014, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

 

 

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9. Earnings Per Share

 

 

 

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10. Commitments and Contingencies

Legal Contingencies

From time to time, TECO Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in which the company or a subsidiary of the company is a defendant in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.

Tampa Electric Legal Proceedings

A thirty-six year old man died from mesothelioma in March 2014. His estate and his family sued Tampa Electric as a result. The man allegedly suffered exposure to asbestos dust brought home by his father and grandfather, both of whom had been employed as insulators and worked at various job sites throughout the Tampa area. Plaintiff’s case against Tampa Electric and fourteen other defendants had alleged, among other things, negligence, strict liability, household exposure, loss of consortium, and wrongful death. On Aug. 6, 2015, Tampa Electric agreed to a settlement which resolved the case in its entirety.

 

A thirty-three year old man made contact with a primary line in June 2013, suffering severe burns. He and his wife are suing Tampa Electric as a result. The man apparently made contact with the line as he was attempting to trim a tree at a local residence.  Plaintiffs' case against Tampa Electric alleges, among other things, negligence and loss of consortium.  Discovery is currently ongoing in the case.

Peoples Gas Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida.  PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in 2016.

New Mexico Gas Company Legal Proceedings

In February 2011, NMGC experienced gas shortages due to weather-related interruptions of electric service, weather-related problems on the systems of various interstate pipelines and in gas fields that are the sources of gas supplied to NMGC, and high weather-driven usage. This gas supply disruption and high usage resulted in the declaration of system emergencies by NMGC causing involuntary curtailments of gas utility service to approximately 28,700 customers (residential and business).  

In March 2011, a customer purporting to represent a class consisting of all “32,000 [sic] customers” who had their gas utility service curtailed during the early-February system emergencies filed a putative class action lawsuit against NMGC. In March 2011, the Town of Bernalillo, New Mexico, purporting to represent a class consisting of all “New Mexico municipalities and governmental entities who have suffered damages as a result of the natural gas utility shut off” also filed a putative class action lawsuit against NMGC, four of its officers, and John and Jane Does at NMGC. In July 2011, the plaintiff in the Bernalillo class action filed an amended complaint to add an additional plaintiff purporting to represent a class of all “similarly situated New Mexico private businesses and enterprises.”  

In September 2015, a settlement was reached with all the named plaintiff class representatives in both of the class actions. The settlements were on an individual basis and not a class basis.

In addition to the two settled class actions described above, eighteen insurance carriers have filed two subrogation lawsuits for monies paid to their insureds as a result of the curtailment of natural gas service in February 2011. These subrogation matters are pending and discovery is proceeding. NMGC has filed motions to dismiss, and the motions are pending.  

TECO Guatemala Holdings, LLC v. The Republic of Guatemala

On Dec. 19, 2013, the ICSID Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (Guatemala) under the DR – CAFTA, issued an award in the case (the Award). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately U.S. $21.1 million, plus interest from

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Oct. 21, 2010 at a rate equal to the U.S. prime rate plus 2%. In addition, the ICSID Tribunal ruled that Guatemala must reimburse TGH for approximately U.S. $7.5 million of the costs that it incurred in pursuing the arbitration.

On Apr. 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules.

Also on Apr. 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the ICSID Tribunal’s determination of the amount of TGH’s damages. If TGH’s application is successful, TGH will be able to seek additional damages from Guatemala in a new arbitration proceeding.

While the duration of the annulment proceedings is uncertain, a hearing was held in October 2015, with a decision by the ad hoc committee expected in mid- to late-2016. Pending the outcome of annulment proceedings, results to date do not reflect any benefit of this decision.

Proceedings in connection with the Pending Merger with Emera

Eleven securities class action lawsuits were filed in September and October 2015 against the company and its directors by holders of TECO Energy securities.  These suits, which were filed in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida, allege that TECO Energy’s board of directors breached its fiduciary duties in agreeing to the Merger Agreement and seek to enjoin the Merger.  In addition, several of these suits allege that one or more of TECO Energy, Emera and an Emera affiliate aided and abetted such alleged breaches. The securities class action lawsuits have been consolidated per court order.  The court's order also indicates that any future actions with allegations and claims substantially similar to those in the initial lawsuits will also be consolidated. Since the consolidation, two of the complaints have been amended. One of those complaints has added a claim against the individual defendants for breach of fiduciary duty to disclose. In addition, one class action lawsuit was filed on Nov. 2, 2015 in the United States District Court for the Middle District of Florida.  In addition to the breach of fiduciary duties and aiding and abetting claims contained in the other lawsuits, this lawsuit alleges violations of Exchange Act rules.

The company also received two separate shareholder demand letters from purported shareholders of the company.  Both of these letters demand that the company maximize shareholder value and remove alleged conflicts of interest as well as eliminate allegedly preclusive deal protection devices.  One of the letters also demands that the company refrain from consummating the transaction with Emera. The outcome of the lawsuits and the demand letters cannot be predicted with any certainty. The company believes that the claims asserted are without merit.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sept. 30, 2015, TEC has estimated its ultimate financial liability to be $33.3 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

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Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation and the year of expiration under letters of credit and guarantees as of Sept. 30, 2015 is as follows:

 

 

Financial Covenants

In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. At Sept. 30, 2015, TECO Energy and its subsidiaries were in compliance with all applicable financial covenants.

 

11. Segment Information

TECO Energy is an electric and gas utility holding company with diversified activities. Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of TECO Energy reports segments based on each subsidiary’s contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related information. Intercompany transactions are eliminated in the Consolidated Condensed Financial Statements of TECO Energy, but are included in determining reportable segments.  

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12. Accounting for Derivative Instruments and Hedging Activities

From time to time, TECO Energy and its affiliates enter into futures, forwards, swaps and option contracts for the following purposes:

TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The regulated utilities’ primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.

The risk management policies adopted by TECO Energy provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies.

The company applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 13). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

The company applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC and NMPRC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).

The company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of Sept. 30, 2015, all of the company’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at Sept. 30, 2015 and Dec. 31, 2014 are reflected on the company’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. Derivative assets totaled $0.2 million and $0.0 as of Sept. 30, 2015 and Dec. 31, 2014, respectively, and derivative liabilities totaled $26.6 million and $42.7 million as of Sept. 30, 2015 and Dec. 31, 2014, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties.

All of the derivative assets and liabilities at Sept. 30, 2015 and Dec. 31, 2014 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at Sept. 30, 2015, net pretax losses of $23.7 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The Sept. 30, 2015 and Dec. 31, 2014 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 8.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three and nine months ended Sept. 30, 2015 and 2014, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three and nine months ended Sept. 30, 2015 and 2014 is presented in Note 8. These gains and losses were the result of interest rate contracts for TEC and diesel fuel derivatives related to TECO Coal operations. The locations of the reclassifications to income were reflected in Interest expense for TEC and Income (loss) from discontinued operations for TECO Coal.

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The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Sept. 30, 2017 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Sept. 30, 2015, are expected to settle during the 2015, 2016 and 2017 fiscal years:

 

The company is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. The company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of Sept. 30, 2015, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.

The company has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. The company generally enters into the following master arrangements: (1) EEI agreements—standardized power sales contracts in the electric industry; (2) ISDA agreements—standardized financial gas and electric contracts; and (3) NAESB agreements—standardized physical gas contracts. The company believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

The company has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as the company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.

Certain TECO Energy derivative instruments contain provisions that require the company’s debt, or in the case of derivative instruments where TEC is the counterparty, TEC’s debt, to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings, including TEC’s, were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The company has no other contingent risk features associated with any derivative instruments.

 

13. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

 

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

 

Level 1:  Observable inputs, such as quoted prices in active markets;

Level 2:  Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and

Level 3:  Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

 

Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance:

 

(A)  Market approach:  Prices and other relevant information generated by market transactions involving

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identical or comparable assets or liabilities;

(B)  Cost approach:  Amount that would be required to replace the service capacity of an asset (replacement

cost); and

(C)  Income approach:  Techniques to convert future amounts to a single present amount based upon market

expectations (including present value techniques, option-pricing and excess earnings models).  

 

The fair value of financial instruments is determined by using various market data and other valuation techniques.  

The following tables set forth by level within the fair value hierarchy, the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Sept. 30, 2015 and Dec. 31, 2014. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.     

 

 

The natural gas derivatives are OTC swap and option instruments.  Fair values of swaps and options are estimated utilizing the market and income approach, respectively.  The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. The price of options is calculated using the Black-Scholes model with observable exchange-traded futures as the primary pricing inputs to the model. Additional inputs to the model include historical volatility, discount rate, and a locational basis adjustment to NYMEX. The resulting prices are applied to the notional quantities of active swap and option positions to determine the fair value (see Note 12). 

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At Sept. 30, 2015, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

 

14. Variable Interest Entities

In the determination of a VIE’s primary beneficiary, the primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 157 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $10.7 million and $26.0 million of capacity pursuant to PPAs for the three and nine months ended Sept. 30, 2015, respectively, and $8.1 million and $20.9 million for the three and nine months ended Sept. 30, 2014, respectively.

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The company does not provide any material financial or other support to any of the VIEs it is involved with, nor is the company under any obligation to absorb losses associated with these VIEs. In the normal course of business, the company’s involvement with these VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

 

15. Discontinued Operations and Asset Impairments

TECO Coal

On Sept. 21, 2015, TECO Energy’s subsidiary, TECO Diversified, entered into an SPA and completed the sale of all of its ownership interest in TECO Coal to Cambrian Coal Corporation.  The SPA did not provide for an up-front purchase payment, but provides for future contingent consideration of up to $60 million that may be paid between 2015 and 2019 if certain coal benchmark prices reach certain levels. TECO Energy retains certain deferred tax assets and personnel-related liabilities, but all other TECO Coal assets and liabilities, including working capital, asset retirement obligations and workers compensation reserves, were transferred in the transaction.  The retained liabilities included pension liability, which was fully funded at Sept. 30, 2015, and severance agreements, which were accrued at June 30, 2015 and paid in the third quarter of 2015. Letters of indemnity related to TECO Coal reclamation bonds will remain in effect until the bonds are replaced by Cambrian, which is expected to be completed in 2016 (see description of guarantees in Note 10).  The company recorded a loss on sale of $10.0 million pretax, which is reflected in discontinued operations in the company’s Consolidated Condensed Statement of Income, primarily to write off an after-tax settlement charge of $7.7 million related to the unfunded black lung obligations previously recorded in AOCI (see Note 5 for additional information). Transaction-related costs of $12.3 million pretax, comprised of $2.5 million of legal and other consultant costs and $9.8 million of severance and other employee costs, were accrued at June 30, 2015 and reflected in discontinued operations in the company’s Consolidated Condensed Statement of Income. The severance and other employee transaction-related costs were paid in the third quarter of 2015, with the exception of a minor amount of severance payments. The legal and other consultant costs will be paid in the fourth quarter of 2015.

In September 2014, the Board of Directors of TECO Energy authorized management to actively pursue the sale of TECO Coal. As a result of this and other factors, the TECO Coal segment was accounted for as an asset held for sale and reported as a discontinued operation beginning in the third quarter of 2014. All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at Parent that directly relate to the sale of TECO Coal.

In 2014, the company recorded impairment charges totaling $115.9 million pretax to write down the held-for-sale TECO Coal assets to their implied fair value. In the second quarter of 2015, based on management’s assessment of current market conditions and discussions with interested parties, an additional impairment charge of $78.6 million pretax was recorded, which included the estimated selling costs associated with this transaction.  

Since the closing of the sale, TECO Energy will not have influence over operations of TECO Coal, therefore the contingent payments are not considered to meet the definition of direct cash flows under the applicable discontinued operations FASB guidance.

The following table provides a summary of the carrying amounts of the significant assets and liabilities reported in the combined current and non-current “Assets held for sale” and “Liabilities associated with assets held for sale” line items:

 

 

TECO Guatemala

In 2012, TECO Guatemala completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods presented reflect the classification of results from operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala as discontinued operations. While TECO Energy and its subsidiaries no longer have assets or operations in Guatemala, its subsidiary, TECO Guatemala Holdings, LLC, has retained its rights under its arbitration claim filed against the Republic of Guatemala (see Note 10). The 2015 charges shown in the table below are legal costs associated with that claim.  Additionally, in March 2014, an indemnification provision for an uncertain tax position at

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TCAE that was provided for in the 2012 purchase agreement was reversed due to a favorable final decision by the highest court in Guatemala, resulting in the income from operations amount shown in the table below.

Combined Components of Discontinued Operations

The following table provides selected components of discontinued operations related to the sales of TECO Coal and TECO Guatemala:

 

 

 

16. Mergers and Acquisitions

Pending Merger with Emera Inc.

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned subsidiary of Emera.

Upon the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation.

Pursuant to the Merger Agreement, upon the closing of the Merger, which is expected to occur by mid-2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt.

The closing of the Merger is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock, (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign Investment in the United States, (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement.

The Merger Agreement contains customary representations, warranties and covenants of TECO Energy, Emera and Merger Sub. The Merger Agreement contains covenants by TECO Energy, among others, that (i) TECO Energy will conduct its business in the ordinary course during the interim period between the execution of the Merger Agreement and the closing of the Merger and (ii) TECO Energy will not engage in certain transactions during such interim period. The Merger Agreement contains covenants by Emera, among others, that Emera will use its reasonable best efforts to take all actions necessary to obtain all governmental and regulatory approvals.

In addition, the Merger Agreement requires Emera (i) to maintain TECO Energy’s historic levels of community involvement and charitable contributions and support in TECO Energy’s existing service territories, (ii) to maintain TECO Energy’s headquarters in Tampa, Florida, (iii) to honor current union contracts in accordance with their terms and (iv) to provide each continuing non-union employee, for a period of two years following the closing of the Merger, with a base salary or wage rate no less favorable than, and incentive compensation and employee benefits, respectively, substantially comparable in the aggregate to those, that they received as of immediately prior to the closing.

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TECO Energy is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties, except under limited circumstances to permit TECO Energy’s board of directors to comply with its fiduciary duties.

The Merger Agreement contains certain termination rights for both TECO Energy and Emera. Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals), (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final, (iii) TECO Energy’s shareholders do not approve the Merger or (iv) TECO Energy’s board of directors changes its recommendation so that it is no longer in favor of the Merger. If either party terminates the Merger Agreement because TECO Energy’s board of directors changes its recommendation, TECO Energy must pay Emera a termination fee of $212.5 million. If the Merger Agreement is terminated under certain other circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.

During the three months ended Sept. 30, 2015, TECO Energy incurred approximately $15.4 million pretax of transaction-related costs, which are included in “Operations and maintenance other expense” on the Consolidated Condensed Statements of Income.

 

Acquisition of New Mexico Gas Company

On Sept. 2, 2014, the company completed the acquisition contemplated by the SPA dated May 25, 2013 by and among the company, NMGI, and Continental Energy Systems LLC. As a result of that acquisition, the company acquired all of the capital stock of NMGI. NMGI is the parent company of NMGC. The aggregate purchase price was $950 million, which included the assumption of $200 million of senior secured notes at NMGC, plus certain working capital adjustments.

Current Quarter and Year-to-Date Impact of NMGI Acquisition

The impact of NMGI and NMGC on the company’s revenues in the Consolidated Statements of Operations for the three months and nine months ended Sept. 30, 2015 was an increase of $43.7 million and $216.7 million, respectively, compared with an increase of $16.2 million for the three and nine months ended Sept. 30, 2014. The impact of NMGI and NMGC on the company’s net income in the Consolidated Statements of Operations for the three months and nine months ended Sept. 30, 2015 was a decrease of $3.9 million and an increase of $7.6 million, respectively, compared with a decrease of $2.0 million for the three and nine months ended Sept. 30, 2014.

Pro Forma Impact of the NMGI Acquisition

The following unaudited pro forma financial information reflects the consolidated results of operations of the company and reflects the amortization of purchase accounting adjustments assuming the acquisition had taken place on Jan. 1, 2013. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the company.

Pro forma earnings presented below include adjustments related to non-recurring acquisition consummation, integration and other costs incurred by the company during the period. After-tax non-recurring acquisition consummation, integration and other costs incurred by the company were $0.9 million and $5.7 million for the three and nine months ended Sept. 30, 2014.

 

 

Transaction and Integration Costs

The following after-tax transaction and integration charges were recognized in connection with the NMGI acquisition and are included in the TECO Energy Consolidated Statements of Operations for the three and nine months ended Sept. 30, 2015 and 2014.

 

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The company has an ongoing severance plan under which, in general, the longer a terminated employee worked prior to termination, the greater the amount of severance benefits. The company records a liability and expense for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the company measures the obligation and records the expense at its fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period.

 

In conjunction with the acquisition, in September 2014, TECO Energy and NMGC each offered a severance plan to certain eligible employees. Severance costs incurred were recorded primarily within Operation and maintenance other expense in the Consolidated Condensed Statements of Income. Cash payments under the severance plan began in the third quarter of 2014, and substantially all cash payments under the plan are expected to be made by the end of 2017 resulting in the substantial completion of the acquisition integration plan. As of Sept. 30, 2015 and Dec. 31, 2014, the obligations associated with the severance benefits costs were $0.3 million and $2.6 million, respectively.

 

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

 

 

The accompanying notes are an integral part of the consolidated condensed financial statements.

 

 

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 TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited

 

 

The accompanying notes are an integral part of the consolidated condensed financial statements.

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

 

 

The accompanying notes are an integral part of the consolidated condensed financial statements.

 

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

 

 

The accompanying notes are an integral part of the consolidated condensed financial statements.

 

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

 

 

The accompanying notes are an integral part of the consolidated condensed financial statements.

 

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TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

 

1. Summary of Significant Accounting Policies

See TEC’s 2014 Annual Report on Form 10-K for a complete discussion of accounting policies. The significant accounting policies for TEC include:

Principles of Consolidation and Basis of Presentation

TEC is a wholly owned subsidiary of TECO Energy, Inc. For the purposes of its consolidated financial reporting, TEC is comprised of the electric division, generally referred to as Tampa Electric, the natural gas division, generally referred to as PGS, and potentially the accounts of VIEs for which it is the primary beneficiary. For the periods presented, no VIEs have been consolidated (see Note 13).

Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of Sept. 30, 2015 and Dec. 31, 2014, and the results of operations and cash flows for the periods ended Sept. 30, 2015 and 2014. The results of operations for the three and nine months ended Sept. 30, 2015 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2015.

The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. The year-end consolidated condensed balance sheet data was derived from audited financial statements; however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP.

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing, TECO Energy will become a wholly owned subsidiary of Emera. See Note 14 for further information.

Revenues

As of Sept. 30, 2015 and Dec. 31, 2014, unbilled revenues of $60.0 million and $49.3 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipts

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $31.7 million and $88.3 million, respectively, for the three and nine months ended Sept. 30, 2015, compared to $31.7 million and $86.7 million, respectively, for the three and nine months ended Sept. 30, 2014.

 

2. New Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This guidance will be effective for TEC beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. TEC is currently evaluating the impact of the adoption of this guidance on its financial statements but does not expect the impact to be significant.

Presentation of Debt Issuance Costs

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability

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rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset, regardless of whether a balance is outstanding. This guidance will be effective for TEC beginning in 2016 and will be required to be applied on a retrospective basis for all periods presented. As of Sept. 30, 2015, $18.5 million of debt issuance costs, which does not include costs for line-of-credit arrangements, are included in “Deferred debits” on TEC’s Consolidated Condensed Balance Sheet.

 

Disclosure of Investments Using Net Asset Value

In May 2015, the FASB issued guidance stating that investments for which fair value is measured using the NAV per share practical expedient should not be categorized in the fair value hierarchy but should be provided to reconcile to total investments on the balance sheet. In addition, the guidance clarifies that a plan sponsor’s pension assets are eligible to be measured at NAV as a practical expedient and that those investments should also not be categorized in the fair value hierarchy. TECO Energy’s pension plan has such investments as disclosed in Note 5 of TEC’s 2014 Annual Report on Form 10-K. This standard will be effective for TEC beginning in 2016 and will be required to be applied on a retrospective basis for all periods presented. TEC is considering adopting the standard for its 2015 fiscal year, as early adoption is permitted.

Measurement Period Adjustments in Business Combinations

In September 2015, the FASB issued guidance requiring an acquirer in a business combination to account for measurement period adjustments during the reporting period in which the adjustment is determined, rather than retrospectively. When measurements are incomplete as of the end of the reporting period covering a business combination, an acquirer may record adjustments to provisional amounts based on events and circumstances that existed as of the acquisition date during the period from the date of acquisition to the date information is received, not to exceed one year. The guidance will be effective for TEC beginning in 2016 and will be applied prospectively. TEC will assess the potential impact of the guidance on future transactions.

 

3. Regulatory

Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

Regulatory Assets and Liabilities

Tampa Electric and PGS apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process.

Details of the regulatory assets and liabilities as of Sept. 30, 2015 and Dec. 31, 2014 are presented in the following table:

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4. Income Taxes

 

TEC is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. TEC’s income tax expense is based upon a separate return computation. TEC’s effective tax rates for the nine months ended Sept. 30, 2015 and 2014 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

The IRS concluded its examination of TECO Energy’s 2013 consolidated federal income tax return in January 2015. The U.S. federal statute of limitations remains open for the year 2012 and forward. Years 2014 and 2015 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2015. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2005 and forward as a result of TECO Energy’s consolidated Florida net operating loss still being utilized.

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5. Employee Postretirement Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5, Employee Postretirement Benefits, in the TECO Energy, Inc. Notes to Consolidated Condensed Financial Statements. TEC’s portion of the net pension expense for the three months ended Sept. 30, 2015 and 2014, respectively, was $3.3 million and $3.6 million for pension benefits, and $1.4 million and $2.6 million for other postretirement benefits. TEC’s portion of the net pension expense for the nine months ended Sept. 30, 2015 and 2014, respectively, was $10.1 million and $11.3 million for pension benefits, and $4.3 million and $7.8 million for other postretirement benefits.  

For the fiscal 2015 plan year, TECO Energy assumed a long-term EROA of 7.00% and a discount rate of 4.256%.  For the Jan. 1, 2015 measurement of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 4.206%. Additionally, TECO Energy made contributions of $55.0 million and $47.5 million to its pension plan in the nine months ended Sept. 30, 2015 and 2014, respectively. TEC’s portion of the contributions was $43.9 million and $38.2 million, respectively. In addition, in October 2015, TECO Energy made a contribution of $43.4 million to the SERP’s trust in order to fully fund its SERP obligation following the signing of the Merger Agreement with Emera. The execution of the Merger Agreement constituted a potential change in control under the trust; therefore, TECO Energy is required to maintain such funding as of the end of each calendar year, including 2015. The fully funded amount is equal to the aggregate present value of all benefits then in pay status under the SERP plus all benefits that would become payable under the SERP to current participants. TEC’s portion of the SERP contribution was $14.9 million.

Included in the benefit expenses discussed above, for the three and nine months ended Sept. 30, 2015, TEC reclassified $2.3 million and $7.0 million, respectively, of prior service benefit and actuarial losses from regulatory assets to net income, compared with $2.6 million and $7.8 million for the three and nine months ended Sept. 30, 2014, respectively.

 

6. Short-Term Debt

At Sept. 30, 2015 and Dec. 31, 2014, the following credit facilities and related borrowings existed:

 

At Sept. 30, 2015, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2014 was 0.7%. There were no outstanding borrowings at Sept. 30, 2015.

Tampa Electric Company Accounts Receivable Facility

On Mar. 24, 2015, TEC and TRC amended and restated their $150 million accounts receivable collateralized borrowing facility in order to (i) appoint The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (BTMU), as Program Agent, replacing the previous Program Agent, Citibank, N.A., (ii) add new lenders, and (iii) extend the scheduled termination date from Apr. 14, 2015 to Mar. 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement dated as of Mar. 24, 2015 between TEC and TRC and (b) a Loan and Servicing Agreement dated as of Mar. 24, 2015, among TEC as Servicer, TRC as Borrower, certain lenders named therein and BTMU, as Program Agent (the Loan Agreement). Under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding in the case of default. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of Sept. 30, 2015, TEC and TRC were in compliance with the requirements of the agreement.  

 

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7. Long-Term Debt

Fair Value of Long-Term Debt

At Sept. 30, 2015, TEC’s total long-term debt had a carrying amount of $2,263.2 million and an estimated fair market value of $2,466.3 million. At Dec. 31, 2014, TEC’s total long-term debt had a carrying amount of $2,097.1 million and an estimated fair market value of $2,372.2 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments (see Note 11 for information regarding the fair value hierarchy).

Issuance of TEC 4.20% Notes due 2045

On May 20, 2015, TEC completed an offering of $250 million aggregate principal amount of 4.20% Notes due May 15, 2045 (the Notes).  The Notes were sold at 99.814% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $246.8 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Until Nov. 15, 2044, TEC may redeem all or any part of the Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.  At any time on or after Nov. 15, 2044, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

 

8. Commitments and Contingencies

Legal Contingencies

From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.

Tampa Electric Legal Proceedings

A thirty-six year old man died from mesothelioma in March 2014. His estate and his family sued Tampa Electric as a result. The man allegedly suffered exposure to asbestos dust brought home by his father and grandfather, both of whom had been employed as insulators and worked at various job sites throughout the Tampa area. Plaintiff’s case against Tampa Electric and fourteen other defendants had alleged, among other things, negligence, strict liability, household exposure, loss of consortium, and wrongful death. On Aug. 6, 2015, Tampa Electric agreed to a settlement which resolved the case in its entirety.

 

A thirty-three year old man made contact with a primary line in June 2013, suffering severe burns. He and his wife are suing Tampa Electric as a result. The man apparently made contact with the line as he was attempting to trim a tree at a local residence.  Plaintiffs' case against Tampa Electric alleges, among other things, negligence and loss of consortium.  Discovery is currently ongoing in the case.

Peoples Gas Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida.  PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in 2016.

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Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sept. 30, 2015, TEC has estimated its ultimate financial liability to be $33.3 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of Sept. 30, 2015 is as follows:

 

 

Financial Covenants

In order to utilize its bank credit facilities, TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At Sept. 30, 2015, TEC was in compliance with all applicable financial covenants.

 

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9. Segment Information

 

 

 

 

10. Accounting for Derivative Instruments and Hedging Activities

From time to time, TEC enters into futures, forwards, swaps and option contracts for the following purposes:

TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.

The risk management policies adopted by TEC provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies.

TEC applies the accounting standards for derivative instruments and hedging activities. These standards require companies to

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recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 11). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

TEC applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of Sept. 30, 2015, all of TEC’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at Sept. 30, 2015 and Dec. 31, 2014 are reflected on TEC’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. Derivative assets totaled $0.0 as of Sept. 30, 2015 and Dec. 31, 2014, and derivative liabilities totaled $26.6 million and $42.7 million as of Sept. 30, 2015 and Dec. 31, 2014, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties.

All of the derivative assets and liabilities at Sept. 30, 2015 and Dec. 31, 2014 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at Sept. 30, 2015, net pretax losses of $23.9 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The Sept. 30, 2015 and Dec. 31, 2014 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 12.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three and nine months ended Sept. 30, 2015 and 2014, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three and nine months ended Sept. 30, 2015 and 2014 is presented in Note 12. Gains and losses were the result of interest rate contracts and the reclassifications to income were reflected in Interest expense.

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Sept.30, 2017 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of Sept. 30, 2015, are expected to settle during the 2015, 2016 and 2017 fiscal years:

 

TEC is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. TEC manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material

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financial loss. However, as of Sept. 30, 2015, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated.

TEC has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. TEC generally enters into the following master arrangements: (1) EEI agreements—standardized power sales contracts in the electric industry; (2) ISDA agreements—standardized financial gas and electric contracts; and (3) NAESB agreements—standardized physical gas contracts. TEC believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.

Certain TEC derivative instruments contain provisions that require TEC’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. TEC has no other contingent risk features associated with any derivative instruments.

 

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

 

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

 

Level 1:  Observable inputs, such as quoted prices in active markets;

Level 2:  Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and

Level 3:  Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

 

Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance:

 

(A)  Market approach:  Prices and other relevant information generated by market transactions involving

identical or comparable assets or liabilities;

(B)  Cost approach:  Amount that would be required to replace the service capacity of an asset (replacement

cost); and

(C)  Income approach:  Techniques to convert future amounts to a single present amount based upon market

expectations (including present value techniques, option-pricing and excess earnings models).

  

The fair value of financial instruments is determined by using various market data and other valuation techniques.  

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The following tables set forth by level within the fair value hierarchy, TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Sept. 30, 2015 and Dec. 31, 2014. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TEC’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  

 

Natural gas swaps are OTC swap instruments. The fair value of the swaps is estimated utilizing the market approach. The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. These prices are applied to the notional quantities of active positions to determine the reported fair value (see Note 10).

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At Sept. 30, 2015, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

 

12. Other Comprehensive Income

 

 

 

 

 

13. Variable Interest Entities

In the determination of a VIE’s primary beneficiary, the primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

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TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 157 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $10.7 million and $26.0 million of capacity pursuant to PPAs for the three and nine months ended Sept. 30, 2015, respectively, and $8.1 million and $20.9 million for the three and nine months ended Sept. 30, 2014, respectively.

TEC does not provide any material financial or other support to any of the VIEs it is involved with, nor is TEC under any obligation to absorb losses associated with these VIEs. In the normal course of business, TEC’s involvement with these VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

14. Mergers and Acquisitions

Pending Merger with Emera Inc.

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned subsidiary of Emera.

Upon the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation.

Pursuant to the Merger Agreement, upon the closing of the Merger, which is expected to occur by mid-2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt (of which TEC’s portion of debt was $2.3 billion).

The closing of the Merger is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock, (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign Investment in the United States, (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement.

TECO Energy is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties, except under limited circumstances to permit TECO Energy’s board of directors to comply with its fiduciary duties.

The Merger Agreement contains certain termination rights for both TECO Energy and Emera. Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals), (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final, (iii) TECO Energy’s shareholders do not approve the Merger or (iv) TECO Energy’s board of directors changes its recommendation so that it is no longer in favor of the Merger. If either party terminates the Merger Agreement because TECO Energy’s board of directors changes its recommendation, TECO Energy must pay Emera a termination fee of $212.5 million. If the Merger Agreement is terminated under certain other circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.

 

 

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This Management’s Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on the company's current expectations and assumptions, and the company does not undertake to update that information or any other  information contained in this Management’s Discussion & Analysis, except as may be required by law. Factors that could affect impact actual results include certain risks and uncertainties associated with the acquisition by Emera (the Merger), including, without limitation:  the occurrence of any event, change, or other circumstance that could give rise to the termination of the Merger Agreement or could otherwise cause the failure of the Merger to close;  the failure to obtain regulatory approvals required for the Merger, or required regulatory approvals delaying the Merger or causing the parties to abandon the Merger; the failure by Emera to obtain the financing necessary to complete the Merger; risks related to disruption of management’s attention from the company’s ongoing business operations due to the Merger; the outcome of any legal proceeding, regulatory proceeding, or enforcement matter that has been or may be instituted against the company, the company’s board of directors, and others relating to the Merger; the risk that the pendency of the Merger disrupts current plans and operations and the potential difficulties in employee retention as a result of the pendency of the Merger; the effect of the Merger on the company’s relationships with its customers, operating results, and business; the amount of the costs, fees, expenses, and charges related to the Merger; the receipt of an unsolicited offer from another party to acquire assets or capital stock of TECO Energy that could interfere with the Merger; and future regulatory or legislative actions that could adversely affect the company’s participation in the Merger.  Other factors that could impact actual results include: regulatory actions by federal, state or local authorities; the ability to successfully implement the integration plans for NMGC and generate the financial results to make the acquisition accretive; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required; general economic conditions affecting customer growth and energy sales at the utility companies; economic conditions affecting the Florida and New Mexico economies; weather variations and customer energy usage patterns affecting sales and operating costs at the utilities and the effect of weather conditions on energy consumption; the effect of extreme weather conditions or hurricanes; general operating conditions; input commodity prices  affecting cost at all of the operating companies; natural gas demand at the utilities; and the ability of TECO Energy's subsidiaries to operate equipment without undue accidents, breakdowns or failures.  Additional information is contained under "Risk Factors" in TECO Energy, Inc.'s Annual Report on Form 10-K for the period ended Dec. 31, 2014, and in Item 1A, Risk Factors of Part II of the Quarterly Report on Form 10-Q for the period ended Sept. 30, 2015.

 

Operating Results

Three Months Ended Sept. 30, 2015

Third-quarter 2015 net income was $53.2 million, or $0.23 per share, compared with $11.1 million, or $0.04 per share, in the third quarter of 2014.  Net income from continuing operations was $64.9 million, or $0.28 per share, in the 2015 third quarter, compared with $73.0 million, or $0.32 per share, for the same period in 2014. Third quarter 2015 results included $0.2 million of NMGC integration costs and $12.2 million of costs related to the pending acquisition of TECO Energy by Emera, compared with $0.9 million of NMGC integration and acquisition-related costs (see Note 16 to the TECO Energy Consolidated Financial Statements). The third quarter loss in discontinued operations of $11.7 million and $61.9 million in 2015 and 2014, respectively, reflects the

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operating results and charges associated with TECO Coal, which was sold on Sept. 21, 2015 (see Note 15 to the TECO Energy Consolidated Financial Statements).

Nine Months Ended Sept. 30, 2015

Year-to-date net income was $123.0 million, or $0.53 per share, compared with net income of $119.6 million, or $0.54 per share in the 2014 period.  Net income from continuing operations was $190.2 million or $0.81 per share, compared with $179.0 million or $0.81 per share in the 2014 period. Year-to-date 2015 results included $1.2 million of NMGC integration costs and $12.2 million of costs related to the pending acquisition of TECO Energy by Emera, compared with $5.7 million of NMGC integration and acquisition-related costs. The year-to-date losses from discontinued operations were $67.2 million and $59.4 million in 2015 and 2014, respectively.

Operating Company Results

All amounts included in the operating company discussions below are after tax, unless otherwise noted.

Tampa Electric Company – Electric Division

Tampa Electric’s net income for the third quarter of 2015 was $82.1 million, compared with $79.7 million for the same period in 2014.  Results for the quarter reflected a 1.8% higher average number of customers partially offset by slightly lower energy sales primarily due to rainy summer weather. Results reflected operations and maintenance expense virtually unchanged from 2014 and higher depreciation expense. Third-quarter net income in 2015 included $4.6 million of AFUDC-equity, which represents allowed equity cost capitalized to construction costs, compared with $2.9 million in the 2014 quarter.

Total degree days in Tampa Electric's service area in the third quarter of 2015 were 1% above normal,  and 2% above the 2014 period. Rainfall, which reduces energy sales, in the Tampa area in the third quarter was 60% above normal. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing-cycle measurement, decreased 0.3% in the third quarter of 2015, compared with the same period in 2014. In the 2015 period, pretax base revenues were more than $1 million higher than in 2014, driven by customer growth and almost $2 million of higher pretax base revenue from the $7.5 million of higher base rates effective Nov. 1, 2014, as a result of the 2013 rate case settlement, partially offset by lower energy sales.  (The quarterly energy sales shown on the following table reflect the energy sales based on the timing of billing cycles, which can vary period to period.) Retail energy sales to residential and commercial customers decreased primarily from rainy weather partially offset by customer growth.  Sales to non-phosphate industrial customers increased due to the strength of the Tampa area economy.  Sales to lower-margin industrial-phosphate customers decreased as self-generation by those customers increased.  

Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was essentially unchanged from the 2014 quarter, reflecting $5.1 million of higher costs to safely and reliably operate and maintain the generating, transmission and distribution systems, offset by lower employee-related costs, primarily due to the timing of short-term incentive accruals for all employees in 2015 compared to 2014.   Depreciation and amortization expense increased $1.7 million in 2015, as a result of normal additions to facilities to reliably serve customers.  

Year-to-date net income was $198.0 million, compared with $187.1 million in the 2014 period, driven by 1.8% higher average number of customers, higher energy sales from customer growth, more favorable weather and a stronger economy, partially offset by higher operations and maintenance and depreciation expenses. Year-to-date net income in 2015 included $12.1 million of AFUDC-equity, compared with $7.3 million in the 2014 period.

Year-to-date total degree days in Tampa Electric's service area were 7% above normal and 10% above the prior year-to-date period.  Pretax base revenue was almost $22 million higher than in 2014, including approximately $5 million of higher pretax base revenue as a result of the Nov.1, 2014, base rate increase. In the 2015 year-to-date period, total net energy for load was 2.5% higher than the same period in 2014. Higher energy sales were driven by hotter than normal 2015 spring weather, and winter weather that was colder than in 2014.

Operations and maintenance expenses, excluding all FPSC-approved cost-recovery clauses, increased $4.7 million in the 2015 year-to-date period reflecting approximately $8.0 million of higher costs to safely and reliably serve customers partially offset by lower employee-related expenses. Compared to the 2014 year-to-date period, depreciation and amortization expense increased $3.6 million, reflecting additions to facilities to serve customers.  Interest expense increased $1.3 million due to higher long-term debt balances.

A summary of Tampa Electric’s regulated operating statistics for the three and nine months ended Sept. 30, 2015 and 2014 follows:

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Tampa Electric Company – Natural Gas Division

PGS reported net income of $6.2 million for the third quarter, compared with $4.8 million in the 2014 quarter. Average customer growth was 2.0% in the quarter, and therm sales to retail customers increased as a result of customer growth and a stronger economy.  Third-quarter results in 2015 reflected non-fuel operations and maintenance expense $1.0 million lower than in the 2014 period, driven by lower employee-related costs, primarily due to the timing of short-term incentive accruals for all employees in 2015 compared to 2014. Depreciation and amortization increased slightly due to normal additions to facilities to serve customers.  Sales to power-generation customers and off-system sales increased due to coal-to-gas switching by customers and new gas-fired generation in the state.

PGS reported net income of $28.4 million for the year-to-date period, compared with $26.9 million in the 2014 year-to-date period. Results reflect a 2.1% higher average number of customers, lower therm sales to residential customers due to warmer than normal spring weather, and increased commercial therm sales due to strong economic conditions in Florida. Sales to power generation customers and off-system sales increased due to the same reasons as in the third quarter.  Non-fuel operations and maintenance expense decreased $0.5 million compared to the 2014 period, driven by lower general operating costs.  Operations and maintenance expense in 2014 reflected a first-quarter recovery of $1.6 million of costs incurred in connection with a 2010 outage incident.

A summary of PGS’s regulated operating statistics for the three and nine months ended Sept. 30, 2015 and 2014 follows:

 

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New Mexico Gas Company

NMGC reported a third-quarter loss of $2.8 million, which was less than historical third-quarter loss patterns. Results reflected the benefit of 0.8% customer growth, and lower operating and maintenance expenses from acquisition synergies and a focus on cost control.  Results in 2014 reflected the loss in the first month of ownership, September, following the closing of the acquisition.

NMGC reported year-to-date 2015 net income of $11.0 million. Results reflected customer growth of 0.7%, much milder than normal winter weather in the first quarter, and degree days 6.7% below normal and 1.4% below 2014.  Operations and maintenance expense was lower than in the 2014 period from acquisition synergies and a focus on cost control. Results included $1.4 million of pretax rate credits to customers under the Certification of Stipulation approved by the NMPRC.

A summary of NMGC’s regulated operating statistics for the three and nine months ended Sept. 30, 2015 and 2014 follows:

 

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(1)     The full period information presented for 2014 is for comparative purposes only, as TECO Energy’s ownership began on the acquisition date of Sept. 2, 2014.

Other (net)

The third quarter 2015 cost from continuing operations for Other – net of $20.6 million included $12.2 million of transaction costs related to the pending Emera acquisition and $0.2 million of costs associated with the integration of NMGC, compared with the cost of $10.6 million in 2014, which included $0.9 million of NMGC-related costs. Although third-quarter results in 2015 reflected $1.1 million of interest expense at NMGI, the parent company of NMGC, and $1.0 million of interest expense previously allocated to TECO Coal, this was more than offset by lower interest expense as a result of refinancing debt maturities in May.

The 2015 year-to-date cost from continuing operations for Other – net was $47.2 million, which included the third quarter transaction costs related to the pending Emera acquisition and $1.2 million of NMGC integration-related costs, compared with $34.1 million in 2014, which included $5.7 million of NMGC acquisition-related costs. Cost drivers in the 2015 year-to-date period included $3.3 million of interest at NMGI, $3.0 million of interest previously allocated to TECO Coal that was offset by lower interest expense, and a $2.6 million tax expense related to long-term incentive compensation shares that vested below target levels.

The segment data in Note 11 to the TECO Energy Consolidated Condensed Financial Statements presents Other and Eliminations as separate segments. The discussion above nets the two segments.

 

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Discontinued Operations – TECO Coal

On Sept. 21, 2015, TECO Diversified, a wholly owned subsidiary of TECO Energy, entered into an SPA for the sale of TECO Coal to Cambrian Coal Corporation. The SPA did not provide for an up-front purchase payment, but provides for contingent payments of up to $60 million that may be paid between 2015 and 2019 depending on specified coal benchmark prices. TECO Energy retains certain personnel related liabilities, but all other TECO Coal liabilities were transferred in the transaction. The retained liabilities included pension liability, which was fully funded at June 30, 2015, and severance agreements, which were accrued at June 30, 2015. The SPA called for a simultaneous signing and closing, which occurred on Sept. 21, 2015.

As a result of the agreement to sell TECO Coal, those operations were classified as discontinued operations effective in the third quarter of 2014 (see Note 15 to the TECO Energy Consolidated Financial Statements).

The third quarter 2015 loss of $11.7 million recorded in discontinued operations reflects TECO Coal’s operating results prior to its sale and a previously disclosed $7.7 million charge related to black lung liabilities.

The year-to-date loss of $67.2 million in discontinued operations reflects TECO Coal’s operating loss, net impairment charges of $50.8 million recorded in the second quarter and the third-quarter black-lung related charge.

 

2015 Guidance from Continuing Operations

TECO Energy continues to expect to deliver consolidated non-GAAP earnings-per-share from continuing operations in a range between $1.08 and $1.11 in 2015.  TECO Energy expects earnings in 2015 to be driven by the factors discussed when guidance was initially provided in early 2015.

 

Preliminary 2016 Business Drivers

Results in 2016 are expected to be driven by customer growth trends for all three utilities at or above the trends experienced in 2015.  Tampa Electric and PGS are expected to continue to earn toward the upper end of their allowed Return on Equity ranges of 9.25% to 11.25% and 9.75% to 11.75%, respectively. Depreciation expense at all three utilities is expected to increase from normal additions to facilities to safely and reliably serve customers.  Tampa Electric expects higher AFUDC-equity earnings from the growing investment in the Polk Power Station conversion project.  

Income Taxes

The provisions for income taxes from continuing operations for the nine month periods ended Sept. 30, 2015 and 2014 were $122.1 million and $98.0 million, respectively. The provision for income taxes for the nine months ended Sept. 30, 2015 was impacted by higher operating income.

 

Pending Acquisition by Emera

On Sept. 4, 2015, TECO Energy, Emera and Merger Sub entered into the Merger Agreement. The following description of the Merger Agreement is not a complete description thereof and is qualified in its entirety by reference to the full text of the Merger Agreement.

Upon the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation.

Pursuant to the Merger Agreement, upon the closing of the Merger, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest.

Upon the closing of the Merger, each outstanding option to purchase shares of TECO Energy common stock under TECO Energy’s stock plans, whether vested or unvested, will be cancelled and converted into the right to receive a lump-sum cash payment equal to the product of the excess, if any, of (i) $27.55, without interest, over (ii) the per-share exercise price of such option, multiplied by the total number of shares of TECO Energy common stock underlying such option. Upon the closing of the Merger, each outstanding restricted share of, or restricted share unit with respect to, TECO Energy common stock will vest (with any performance goals deemed achieved at the maximum level) and will be cancelled and converted automatically into the right to receive a lump-sum cash payment equal to $27.55, without interest. Each such payment will be made upon the closing, except that the post-closing portion of each such payment with respect to each restricted share unit granted to employees after Sept. 4, 2015 will be made as promptly as practicable following the vesting date applicable to such unit.

The closing of the Merger is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock, (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the

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Committee on Foreign Investment in the United States, (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement.

The Merger Agreement contains certain termination rights for both TECO Energy and Emera. Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals), (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final, (iii) TECO Energy’s shareholders do not approve the Merger or (iv) TECO Energy’s board of directors changes its recommendation so that it is no longer in favor of the Merger. If either party terminates the Merger Agreement because TECO Energy’s board of directors changes its recommendation, TECO Energy must pay Emera a termination fee of $212.5 million. If the Merger Agreement is terminated under certain other circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.

Liquidity and Capital Resources

The table below sets forth the Sept. 30, 2015 consolidated liquidity and cash balances, the cash balances at the operating companies and TECO Energy parent, and amounts available under the TECO Energy/TECO Finance, TEC and NMGC credit facilities.

 

Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy and its subsidiaries must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. At Sept. 30, 2015, TECO Energy and its subsidiaries were in compliance with all required financial covenants. The table that follows lists the significant financial covenants and the performance relative to them at Sept. 30, 2015. Reference is made to the specific agreements and instruments for more details.

 

Significant Financial Covenants

 

 

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Credit Ratings of Senior Unsecured Debt at Sept. 30, 2015

 

On Oct. 27, 2014, S&P placed the issuer credit rating of TECO Energy and the senior unsecured debt rating of its subsidiaries, TECO Finance, TEC and NMGC on credit watch with positive implications, following the announcement of the agreement to sell TECO Coal. On July 6, 2015, S&P removed the TECO Energy issuer credit rating from credit watch positive and affirmed all credit ratings after the expiration of the letter agreement to sell TECO Coal.  S&P also described the outlook as positive on Tampa Electric, NMGC, and TECO Energy. On July 17, 2015, S&P revised the outlook for TECO Energy and its subsidiaries from positive to developing and affirmed all credit ratings in response to TECO Energy’s confirmation that it was exploring strategic alternatives.  On Sept. 8, 2015, S&P affirmed the issuer credit rating of TECO Energy and the senior unsecured debt rating of its subsidiaries, TECO Finance, TEC and NMGC and revised the outlook to negative from developing, following the announcement of the pending Merger with Emera.  

 

On Sept. 8, 2015, Moody’s Investors Service, Inc. announced that the pending Merger with Emera had no immediate impact on the senior unsecured debt ratings of TECO Energy and subsidiaries.  

 

On Sept. 8, 2015, Fitch Ratings affirmed the issuer default ratings of TECO Energy and the senior unsecured debt rating of its subsidiaries, TECO Finance and TEC, following the announcement of the pending Merger with Emera. On Oct. 9, 2015, Fitch Ratings affirmed the issuer default ratings of TECO Energy at BBB and TEC at BBB+ and affirmed the senior unsecured debt rating of its subsidiaries, TECO Finance and TEC. Fitch Ratings also described the ratings outlook as "Stable".

S&P, Moody’s and Fitch describe credit ratings in the BBB or Baa category as representing adequate capacity for payment of financial obligations. The lowest investment grade credit ratings for S&P is BBB-, for Moody’s is Baa3 and for Fitch is BBB-; thus, the credit rating agencies assign TECO Energy, TECO Finance, TEC and NMGC’s senior unsecured debt investment-grade credit ratings.  

A credit rating agency rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Our access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of our securities. In addition, certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings (see Note 12 to the TECO Energy Consolidated Financial Statements). The credit ratings listed above are included in this report in order to provide information that may be relevant to these matters and because downgrades, if any, in credit ratings may affect our ability to borrow and may increase financing costs, which may decrease earnings (see the Risk Factors section). These credit ratings are not necessarily applicable to any particular security that we may offer and therefore should not be relied upon for making a decision to buy, sell or hold any of our securities.

Fair Value Measurements

All natural gas derivatives were entered into by the regulated utilities to manage the impact of natural gas prices on customers. As a result of applying accounting standards for regulated operations, the changes in value of natural gas derivatives of Tampa Electric, PGS and NMGC are recorded as regulatory assets or liabilities to reflect the impact of the risks of hedging activities in the fuel recovery clause. Because the amounts are deferred and ultimately collected through the fuel clause, the unrealized gains and losses associated with the valuation of these assets and liabilities do not impact our results of operations.

The valuation methods used to determine fair value are described in Notes 7 and 13 to the TECO Energy Consolidated Condensed Financial Statements. In addition, the company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At Sept. 30, 2015, the fair value of derivatives was not materially affected by nonperformance risk.

Critical Accounting Policies and Estimates

The company’s critical accounting policies relate to deferred income taxes, employee postretirement benefits, long-lived assets, goodwill, purchase accounting and regulatory accounting. For further discussion of critical accounting policies, see TECO Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2014.

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Environmental

Tampa Electric produces ash and other by-products, collectively known as CCRs. The CCRs produced at Big Bend include fly ash, FGD gypsum, boiler slag, bottom ash and economizer ash. The CCRs produced at the Polk Power Station include gasifier slag and sulfuric acid. Overall, greater than 95% of all CCRs produced at these facilities were marketed to customers for beneficial use in commercial and industrial products. The remaining 5% were either disposed of onsite or shipped offsite to nearby industrial waste landfills in Central Florida.

The U.S. EPA published a new CCR rule in the Federal Register on Apr. 17, 2015 setting federal standards for companies that dispose of CCRs in onsite landfills and impoundments. The rule went into effect on Oct. 19, 2015 and contains design and operating standards for CCR management units. Tampa Electric is currently evaluating various options for demonstrating compliance with the rule.  The initial assessment is that activities in 2015 and 2016 will consist primarily of monitoring and testing of the two existing CCR impoundments that are affected by this rule.  Potential capital expenditures that may be required to comply with this rule are not expected to be significant.  Under current Florida regulation, compliance related expenditures and capital investments related to complying with this new rule would be recoverable under the state’s Environmental Cost Recovery Clause. This rule is likely to face continued legal challenges by the utility industry and environmental groups, and legislation is required to fix certain portions of the rule.  At this time, the ultimate outcome of any litigation or legislation is uncertain and it is not possible to predict the ultimate impact on Tampa Electric at this time.

On June 29, 2015, the U.S. Supreme Court remanded the EPA’s Mercury and Air Toxics Standard (MATS) to the U.S. District of Columbia Circuit Court for failing to properly consider the cost of compliance.  The Circuit Court must now decide whether to vacate or stay the rule and require EPA to submit further cost benefit analysis. Many utilities had already taken steps to comply with the rule; therefore the Supreme Court’s decision is not expected to have a material effect on the utility industry.

All of Tampa Electric’s conventional coal-fired units are already equipped with scrubbers and SCRs, and the Polk Unit 1 IGCC unit emissions are minimized in the gasification process. Tampa Electric is uniquely positioned to be able to meet the MATS standards without considerable impacts, compared to others who have not taken similar early actions. Therefore, Tampa Electric expects the co-benefits of these control devices for mercury removal to minimize the impact of this rule and expects that it will be in compliance with MATS with nominal additional capital investment.

After the completion of a study into wastewater discharges by the electric utility industry in 2009, the EPA announced its intent to revise the existing steam electric effluent limit guidelines (ELGs) that place technology-based limits on wastewater discharges. A pre-publication copy of the final rule was released on Sept. 30, 2015.  The ELGs establish limits for wastewater discharges from flue gas desulfurization (FGD) processes, fly ash and bottom ash transport water, leachate from ponds and landfills containing CCRs, gasification processes, and flue gas mercury controls. For FGD wastewater, EPA imposed limits for arsenic, mercury, selenium, and nitrate/nitrite which will require the addition of biological treatment at Big Bend Station.  Both fly ash and bottom ash transport water have been designated as zero discharge wastewaters, with the exception of use as make-up water in FGD scrubber.  Transport water used as make-up will be subject to FGD wastewater limits at the point of discharge.  New limits for gasification processes will likely require additional treatment at Polk Power Station. Cost estimates are being developed based on an evaluation of treatment technologies required to meet the pollutant limits. The new guidelines are expected to be incorporated into NPDES permit renewals to achieve compliance as soon as possible after Nov. 1, 2018, but no later than Dec. 31, 2023.

On Sept. 30, in response to a court order, the U.S. EPA published a final rule revising the ground level ozone standard to 70 parts per billion from the previous level of 75 parts per billion.  Compliance with the new standard will be the responsibility of individual states, which will provide flexibility in meeting the standards depending on the severity of each state’s ozone levels.  States will be required to be in compliance between 2020 and 2037.  Until Florida develops a compliance plan it is not possible to estimate the impact of this new standard on the operations of Tampa Electric or to estimate the cost of compliance.

 

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Changes in Fair Value of Derivatives

The change in fair value of derivatives is largely due to settlements of natural gas swaps and the decrease in the average market price component of the company’s outstanding natural gas swaps of approximately 20% from Dec. 31, 2014 to Sept. 30, 2015. For natural gas, the company maintained a similar volume hedged as of Sept. 30, 2015 from Dec. 31, 2014.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the nine month period ended Sept. 30, 2015:

 

Change in Fair Value of Derivatives (millions)

 

Roll-Forward of Derivative Net Assets (Liabilities) (millions)

 

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at Sept. 30, 2015:

For all unrealized derivative contracts, the valuation is an estimate based on the best available information. Actual cash flows could be materially different from the estimated value upon maturity.

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TECO Energy, Inc.

Tampa Electric Company

 

 

 

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PART II. OTHER INFORMATION

 

Item 1. LEGAL PROCEEDINGS

From time to time, TECO Energy and its subsidiaries are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition, or cash flows.

For a discussion of certain legal proceedings and environmental matters, including an update of previously disclosed legal proceedings and environmental matters, see Notes 10 and 8, Commitments and Contingencies, of the TECO Energy and Tampa Electric Company Consolidated Financial Statements, respectively.

Item 1A.    RISK FACTORS

TECO Energy updated the risk factors in its 2014 Annual Report on Form 10-K as described below.

 

Risks Associated with the Acquisition by Emera 

TECO Energy and its subsidiaries will be subject to business uncertainties and contractual restrictions while the Merger is pending that could adversely affect TECO Energy’s financial results.

Uncertainty about the effect of the Merger on employees or vendors and others may have an adverse effect on TECO Energy. Although TECO Energy intends to take steps designed to reduce any adverse effects, these uncertainties may impair TECO Energy’s and its subsidiaries’ ability to attract, retain and motivate key personnel until the Merger is completed, and could cause vendors and others that deal with TECO Energy to seek to change existing business relationships. Employee retention and recruitment may be particularly challenging prior to the completion of the Merger, as current employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite TECO Energy’s retention and recruiting efforts, key employees depart or fail to accept employment with TECO Energy or its subsidiaries due to the uncertainty and difficulty of integration or a desire not to remain with the combined company, TECO Energy’s business operations and financial results could be adversely affected.

TECO Energy expects that matters relating to the Merger and integration-related issues will place a significant burden on management, employees and internal resources, which could otherwise have been devoted to other business opportunities. The diversion of management time on Merger-related issues could affect TECO Energy’s financial results.

In addition, the Merger Agreement restricts TECO Energy and its subsidiaries, without Emera’s prior written consent, from taking specified actions until the Merger occurs or the Merger Agreement is terminated, including, without limitation: (i) making certain material acquisitions and dispositions of assets or businesses; (ii) making any capital expenditures in excess of specified amounts; (iii) incurring indebtedness, subject to certain exceptions; (iv) issuing equity or equity equivalents; and (v) paying quarterly cash dividends in excess of levels agreed upon in the Merger Agreement. These restrictions may prevent TECO Energy from pursuing otherwise attractive business opportunities and making other changes to its business prior to consummation of the Merger or termination of the Merger Agreement.

Pending or potential future litigation against TECO Energy and its directors challenging the proposed Merger may prevent the Merger from being completed within the anticipated timeframe.

Subsequent to the Merger announcement, purported shareholders of TECO Energy filed numerous complaints styled as class action lawsuits in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida.  The complaints allege that the Board breached its fiduciary duties in agreeing to the Merger Agreement and seeks to enjoin the Merger. In addition, each complaint also alleges that some combination of TECO Energy, Emera and Merger Sub aided and abetted such alleged breaches.

The outcome of the lawsuits cannot be predicted with any certainty. A preliminary injunction could delay or jeopardize the completion of the Merger, and an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the Merger. The company believes that the claims asserted in the lawsuits are without merit.

Failure to complete the Merger could negatively impact the market price of TECO Energy’s common stock.

There can be no assurance that the Merger will occur. Failure to complete the Merger may negatively impact the future trading price of TECO Energy’s common stock. If the Merger is not completed, the market price of TECO Energy’s common stock may

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decline to the extent that the current market price of TECO Energy’s stock reflects a market assumption that there is a high probability that the Merger will be completed.

Additionally, if the Merger is not completed, TECO Energy will have incurred significant costs, as well as the diversion of the time and attention of management. A failure to complete the Merger may also result in negative publicity, litigation against TECO Energy or its directors and officers, and a negative impression of TECO Energy in the investment community. The occurrence of any of these events individually or in combination could have a material adverse effect on TECO Energy’s financial condition, results of operations and its stock price.

 

TECO Energy and Emera may be unable to obtain the required shareholder, governmental, regulatory, and other approvals required to complete the Merger.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock, (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period (iii) receipt of all required regulatory approvals, including from FERC, the NMPRC, and the Committee on Foreign Investment in the United States; (iv) the absence of any law or judgement that prevents, makes illegal or prohibits the closing of the Merger; (v) the absence of any material adverse effect with respect to TECO Energy; (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement; and (vii) other customary closing conditions. The shareholder, governmental, regulatory, and other approvals required to consummate the Merger may not be obtained at all, or may not be obtained on the proposed terms and schedules as contemplated by the parties.  Satisfaction of the closing conditions may delay the consummation of the Merger, and if certain closing conditions are not satisfied prior to the outside date specified in the Merger Agreement, Emera will not be obligated to consummate the Merger.

 

In the event that the Merger Agreement is terminated prior to the completion of the Merger, TECO Energy could incur significant transaction costs that could materially impact its financial performance and results of operations.

TECO Energy will incur significant transaction costs, including legal, accounting, financial advisory, filing, printing, and other costs relating to the Merger. The Merger Agreement provides that upon termination of the Merger Agreement under certain specified circumstances, TECO Energy will be required to pay Emera a termination fee of $212.5 million. Any fees due as a result of termination could have a material adverse effect on our results of operations, financial condition, and cash flows.

 

General Risks

National and local economic conditions can have a significant impact on the results of operations, net income and cash flows at TECO Energy and its subsidiaries.

The business of TECO Energy is concentrated in Florida and New Mexico. While economic conditions in Florida and New Mexico have shown indications of improvement, if they do not continue to improve or if they should worsen, retail customer growth rates may stagnate or decline, and customers’ energy usage may further decline, adversely affecting TECO Energy’s results of operations, net income and cash flows.

Developments in technology could reduce demand for electricity and gas.

Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-oriented generation, energy storage, energy efficiency and more energy efficient appliances and equipment. Advances in these, or other technologies, could reduce the cost of producing electricity or transporting gas, or otherwise make the existing generating facilities of Tampa Electric uneconomic. In addition, advances in such technologies could reduce demand for electricity or natural gas, which could negatively impact the results of operations, net income and cash flows of TECO Energy.

TECO Energy’s businesses are sensitive to variations in weather and the effects of extreme weather, and have seasonal variations.

TECO Energy’s businesses are affected by variations in general weather conditions and unusually severe weather. Energy sales by its electric and gas utilities are particularly sensitive to variations in weather conditions. Those companies forecast energy sales on the basis of normal weather, which represents a long-term historical average. If climate change or other factors cause significant variations from normal weather, this could have a material impact on energy sales.

PGS and NMGC, which typically have short but significant winter peak periods that are dependent on cold weather, are more weather-sensitive than Tampa Electric, which has both summer and winter peak periods. NMGC typically earns all of its net income in the first and fourth quarters, due to winter weather. Mild winter weather could negatively impact results at TECO Energy.

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TECO Energy’s electric and gas utilities are highly regulated; changes in regulation or the regulatory environment could reduce revenues or increase costs or competition.

TECO Energy’s electric and gas utilities operate in highly regulated industries. Their retail operations, including the prices charged, are regulated by the FPSC in Florida and the NMPRC in New Mexico, and Tampa Electric’s wholesale power sales and transmission services are subject to regulation by the FERC. Changes in regulatory requirements or adverse regulatory actions could have an adverse effect on TECO Energy’s utilities’ financial performance by, for example, reducing revenues, increasing competition or costs, threatening investment recovery or impacting rate structure.

If Tampa Electric or PGS consistently earn returns on equity above their respective allowed ranges over an extended period of time, indicating an overearnings trend, those earnings could be subject to review by the FPSC. Ultimately, prolonged overearnings could result in credits or refunds to customers, which could reduce earnings and cash flow.

Various factors relating to the integration of NMGC could adversely affect TECO Energy’s business and operations.

Based on the completion of the permanent financing for the NMGC acquisition in 2014, TECO Energy expects NMGC to be accretive to earnings for the full-year 2015 period. However, the anticipated accretion to earnings from NMGC during this integration period was based on estimates of synergies from the transaction and growth in the New Mexico economy, which are dependent on local and global economic conditions, normal weather and other factors, which may materially change, including:

 

 

 

Negative impacts from these factors could have an adverse effect on TECO Energy’s business, financial condition, results of operations or stock price. TECO Energy identified some, but not all, of the actions necessary to achieve its anticipated synergies. Accordingly, the synergies expected from the acquisition of NMGC may not be achievable in its anticipated amount or timeframe or at all.

Changes in the environmental laws and regulations affecting its businesses could increase TECO Energy’s costs or curtail its activities.

TECO Energy’s businesses are subject to regulation by various governmental authorities dealing with air, water and other environmental matters. Changes in compliance requirements or the interpretation by governmental authorities of existing requirements may impose additional costs on TECO Energy, requiring cost-recovery proceedings and/or requiring it to curtail some of its businesses’ activities.

Regulations on the disposal and/or storage of CCRs could add to Tampa Electric’s operating costs.

The U.S. EPA published a new CCR rule in the U.S. Federal Register on Apr. 17, 2015, setting federal standards for companies that dispose of CCRs in onsite landfills and impoundments. The rule went into effect on Oct. 19, 2015, and contains design and operating standards for CCR management units. Tampa Electric is currently evaluating various options for demonstrating compliance with the rule. The initial assessment is that activities in 2015 and 2016 will consist primarily of monitoring and testing of the two existing CCR impoundments that are affected by this rule. Potential capital expenditures that may be required to comply with this rule are not expected to be significant. Under current Florida regulation, compliance-related expenditures and capital investments related to complying with this new rule would be recoverable under Florida’s ECRC. This rule is likely to face continued legal challenges by the utility industry and environmental groups, and legislation is required to fix certain portions of the rule. At this time, the ultimate outcome of any litigation or legislation is uncertain, and it is not possible to predict the ultimate impact on Tampa Electric at this time. While certain costs related to environmental compliance are currently recoverable from customers under Florida’s ECRC, TECO Energy cannot be assured that any increased costs associated with those regulations will be eligible for such treatment.

Federal or state regulation of GHG emissions, depending on how they are enacted, could increase TECO Energy’s costs or the rates charged to TECO Energy customers, which could curtail sales.

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Among TECO Energy’s companies, Tampa Electric has the most significant number of stationary sources with air emissions.

Current regulation in Florida allows utility companies to recover from customers prudently incurred costs for compliance with new state or federal environmental regulations. Tampa Electric would expect to recover from customers the costs of power plant modifications or other costs required to comply with new GHG emission regulation. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric could seek to recover those costs through a base-rate proceeding, but TECO Energy cannot be assured that the FPSC would grant such recovery. Under the Clean Power Plan, each state is to implement its own regulations to accord to the federal standards. As such, Florida’s regulatory landscape may change, which could significantly increase Tampa Electric’s costs. Changes in compliance requirements or the interpretation by governmental authorized existing requirements may impose additional costs on TECO Energy requiring FPSC cost recovery proceedings and/or requiring it to curtail some of its business activities.

The Clean Power Plan establishes state-specific emission rate and mass-based goals measured against a 2012 baseline. As TECO Energy’s investments in lower-GHG production largely occurred before 2012 and are factored into Florida’s baseline generating capacity, TECO Energy may encounter more difficulty than its competitors in achieving cost-effective GHG emission reductions. However, because the ultimate form of Florida’s state plan remains unknown, it is not currently possible to predict the increased compliance costs that TECO Energy may face as a result of the Clean Power Plan.

A mandatory RPS could add to Tampa Electric’s costs and adversely affect its operating results.

In past sessions of the Florida Legislature, an RPS was debated but ultimately not enacted; however, an RPS standard could be enacted in the future. In addition, there is the potential that legislation could be proposed in the U.S. Congress to introduce an RPS at the federal level. It remains unclear if or when action on such legislation would be completed. Tampa Electric could incur significant costs to comply with an RPS, and Tampa Electric’s operating results could be adversely affected if Tampa Electric were not permitted to recover these costs from customers through the ECRC.

A proposed constitutional ballot initiative pending before the Florida Supreme Court to review its constitutionality and any corresponding legislative proposal could, if successful, promote increased direct sale and use of solar energy to generate electricity.

A potential amendment to the Florida constitution in 2016 and potential corresponding 2016 legislation would encourage the installation of solar arrays to generate electricity by retail customers and third parties, and to allow sales of electricity by non-utility generators. Increased use of solar generation and sales by third parties would reduce energy sales and revenues at Tampa Electric. In addition, Tampa Electric could make investments in facilities to serve customers during periods that solar energy is not available that would not be profitable.

NMGC operates high-pressure natural gas transmission pipelines, which involve risks that may result in accidents or otherwise affect its operations.

There are a variety of hazards and operating risks inherent in operating high-pressure natural gas transmission pipelines, such as leaks, explosions, mechanical problems, activities of third parties and damage to pipelines, facilities and equipment caused by floods, fires and other natural disasters that may cause substantial financial losses. In addition, these risks could result in significant injury, loss of life, significant damage to property, environmental pollution and impairment of operations, any of which could result in substantial losses. For pipeline assets located near populated areas, including residential areas, commercial business centers, industrial site and other public gathering areas, known as High Consequence Areas, the level of damage resulting from these risks could be greater. NMGC does not maintain insurance coverage against all of these risks and losses, and any insurance coverage it might maintain may not fully cover damages caused by those risks and losses. Therefore, should any of these risks materialize, it could have a material adverse effect on TECO Energy’s business, earnings, financial condition and cash flows.

NMGC’s high-pressure transmission pipeline operations are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase TECO Energy’s cost of operations and affect or limit its business plans.

TECO Energy’s pipeline operations are subject to pipeline safety regulation administered by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the U.S. Department of Transportation. These laws and regulations require TECO Energy to comply with a significant set of requirements for the design, construction, maintenance and operation of its pipelines. These regulations, among other things, include requirements to monitor and maintain the integrity of its pipelines. The regulations determine the pressures at which its pipelines can operate.

PHMSA is designing an Integrity Verification Process intended to create standards to verify maximum allowable operating pressure, and to improve and expand pipeline integrity management processes. There remains uncertainty as to how these standards will be implemented, but it is expected that the changes will impose additional costs on new pipeline projects as well as on existing operations. Pipeline failures or failures to comply with applicable regulations could result in reduction of allowable operating

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pressures as authorized by PHMSA, which would reduce available capacity on TECO Energy’s pipelines. Should any of these risks materialize, it may have a material adverse effect on TECO Energy’s operations, earnings, financial condition and cash flows.

Results at TECO Energy’s companies may be affected by changes in customer energy-usage patterns.

For the past several years, at Tampa Electric, and electric utilities across the United States, weather-normalized electricity consumption per residential customer declined due to the combined effects of voluntary conservation efforts, economic conditions, improvements in lighting and appliance efficiency, trends toward smaller single family houses and increased multi-family housing.

Forecasts by TECO Energy’s companies are based on normal weather patterns and historical trends in customer energy-usage patterns. The ability of TECO Energy’s utilities to increase energy sales and earnings could be negatively impacted if customers continue to use less energy in response to increased energy efficiency, economic conditions or other factors.

TECO Energy’s computer systems and the infrastructure of its utility companies may be subject to cyber- (primarily electronic or internet-based) or physical attacks, which could disrupt operations, cause loss of important data or compromise customer-, employee-related or other critical information or systems, or otherwise adversely affect its business and financial results and condition.

There have been an increasing number of cyberattacks on companies around the world, which have caused operational failures or compromised sensitive corporate or customer data. These attacks have occurred over the Internet, through malware, viruses, attachments to e-mails, through persons inside of the organization or through persons with access to systems inside of the organization.

TECO Energy has security systems and infrastructure in place that are designed to prevent such attacks, and these systems are subject to internal, external and regulatory audits to ensure adequacy. Despite these efforts, TECO Energy cannot be assured that a cyberattack will not cause electric or gas system operational problems, disruptions of service to customers, compromise important data or systems, or subject it to additional regulation, litigation or damage to its reputation.

There have also been physical attacks on critical infrastructure at other utilities. While the transmission and distribution system infrastructure of TECO Energy’s utility companies are designed and operated in such a manner to mitigate the impact of this type of attack, in the event of a physical attack that disrupts service to customers, revenues would be reduced and costs would be incurred to repair any damage. These types of events, either impacting its facilities or the industry in general, could also cause TECO Energy to incur additional security- and insurance-related costs, and could have adverse effects on its business and financial results and condition.

Potential competitive changes may adversely affect TECO Energy’s regulated electric and gas businesses.

There is competition in wholesale power sales across the United States. Some states have mandated or encouraged competition at the retail level and, in some situations, required divestiture of generating assets. While there is active wholesale competition in Florida, the retail electric business has remained substantially free from direct competition. Although not expected in the foreseeable future, changes in the competitive environment occasioned by legislation, regulation, market conditions or initiatives of other electric power providers, particularly with respect to retail competition, could adversely affect Tampa Electric’s business and its expected performance.

The gas distribution industry has been subject to competitive forces for a number of years. Gas services provided by TECO Energy’s gas utilities are unbundled for all non-residential customers. Because its gas utilities earn margins on distribution of gas but not on the commodity itself, unbundling has not negatively impacted TECO Energy’s results. However, future structural changes that TECO Energy cannot predict could adversely affect PGS and NMGC.

Increased customer use of distributed generation could adversely affect TECO Energy’s regulated electric utility business.

In many areas of the United States, there is growing use of rooftop solar panels, small wind turbines and other small-scale methods of power generation, called distributed generation, by individual residential, commercial and industrial customers. Distributed generation is encouraged and supported by various special interest groups, tax incentives, renewable portfolio standards and special rates designed to support such generation. Additionally, the EPA’s Clean Power Plan could have the effect of providing greater incentives for distributed generation in order to meet state-based emission reduction targets under the proposed rule.

Increased usage of distributed generation, particularly in those states where solar or wind resources are the most abundant, is reducing utility electricity sales but not reducing the need for ongoing investment in infrastructure to maintain or expand the transmission and distribution grid to reliably serve customers. Continued utility investment that is not supported by increased energy sales causes rates to increase for customers, which could further reduce energy sales and reduce profitability.

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The value of TECO Energy’s existing deferred tax benefits are determined by existing tax laws, and could be negatively impacted by changes in these laws.

“Comprehensive tax reform” remains a topic of discussion in the U.S. Congress. Such legislation could significantly alter the existing tax code, including a reduction in corporate income tax rates. Although a reduction in the corporate income tax rate could result in lower future tax expense and tax payments, it would reduce the value of TECO Energy’s existing deferred tax asset and could result in a charge to earnings from the write-down of that asset, and would reduce future cash flow of TECO Energy.

TECO Energy relies on some natural gas transmission assets that it does not own or control to deliver natural gas. If transmission is disrupted, or if capacity is inadequate, TECO Energy’s ability to sell and deliver natural gas and supply natural gas to its customers and its electric generating stations may be hindered.

TECO Energy depends on transmission facilities owned and operated by other utilities and energy companies to deliver the natural gas it sells to the wholesale and retail markets, as well as the natural gas it purchases for use in its electric generation facilities. If transmission is disrupted, or if capacity is inadequate, its ability to sell and deliver products and satisfy its contractual and service obligations may be hindered.

Disruption of fuel supply could have an adverse impact on the financial condition of TECO Energy.

Tampa Electric, PGS and NMGC depend on third parties to supply fuel, including natural gas and coal. As a result, there are risks of supply interruptions and fuel-price volatility. Disruption of fuel supplies or transportation services for fuel, whether because of weather-related problems, strikes, lock-outs, break-downs of locks and dams, pipeline failures or other events, could impair the ability to deliver electricity or gas or generate electricity and could adversely affect operations. Further, the loss of coal suppliers or the inability to renew existing coal and natural gas contracts at favorable terms could significantly affect the ability to serve customers and have an adverse impact on the financial condition and results of operations of TECO Energy.

Commodity price changes may affect the operating costs and competitive positions of TECO Energy’s businesses.

TECO Energy’s businesses are sensitive to changes in coal, gas, oil and other commodity prices. Any changes could affect the prices these businesses charge, their operating costs and the competitive position of their products and services.

In the case of Tampa Electric, fuel costs used for generation are affected primarily by the cost of coal and natural gas. Tampa Electric is able to recover prudently incurred costs of fuel through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.

The ability to make sales and the margins earned on wholesale power sales are affected by the cost of fuel to Tampa Electric, particularly as it compares to the costs of other power producers.

In the case of PGS and NMGC, costs for purchased gas and pipeline capacity are recovered through retail customers’ bills, but increases in gas costs affect total retail prices and, therefore, the competitive position of PGS and NMGC relative to electricity, other forms of energy and other gas suppliers.

The facilities and operations of TECO Energy could be affected by natural disasters or other catastrophic events.

TECO Energy’s facilities and operations are exposed to potential damage and partial or complete loss resulting from environmental disasters (e.g. floods, high winds, fires and earthquakes), equipment failures, vandalism, potentially catastrophic events such as a major accident or incident at one of the sites, and other events beyond the control of TECO Energy. The operation of transmission and distribution systems involves certain risks, including gas leaks, fires, explosions, pipeline ruptures and other hazards and risks that may cause unforeseen interruptions, personal injury or property damage. Any such incident could have an adverse effect on TECO Energy and any costs relating to such events may not be recoverable through insurance or recovered in rates. In certain cases, there is potential that some events may not excuse TECO Energy’s utility subsidiaries from servicing customers as required by their respective tariffs. In addition, TECO Energy may not be able to recover losses resulting from such events through insurance or rates.

The franchise rights held by TECO Energy’s subsidiaries could be lost in the event of a breach by such TECO Energy subsidiary or could expire and not be renewed.

TECO Energy’s subsidiaries hold franchise rights that are memorialized in agreements with selected counterparties throughout the subsidiaries’ service areas. In some cases these rights could be lost in the event of a breach of these agreements by such TECO Energy subsidiary. In addition, these agreements are for set periods and could expire and not be renewed upon expiration of the then-

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current terms. Selected agreements also contain purchase rights allowing municipalities to purchase the corresponding subsidiary’s system within a given municipality’s boundaries under certain conditions.

Tampa Electric, PGS and NMGC may not be able to secure adequate rights of way to construct transmission lines, gas interconnection lines and distribution-related facilities and could be required to find alternate ways to provide adequate sources of energy and maintain reliable service for their customers.

Tampa Electric, PGS and NMGC rely on federal, state and local governmental agencies and, in particular in New Mexico, cooperation with local Native American tribes and councils to secure rights of way and siting permits to construct transmission lines, gas interconnection lines and distribution-related facilities. If adequate rights of way and siting permits to build new transportation and transmission lines cannot be secured:

 

 

 

 

Impairment testing of certain long-lived assets could result in impairment charges.

TECO Energy assesses long-lived assets and goodwill for impairment annually or more frequently if events or circumstances occur that would more likely than not reduce the fair value of those assets below their carrying values. To the extent the value of goodwill or a long-lived asset becomes impaired, TECO Energy may be required to record non-cash impairment charges that could have a material adverse impact on TECO Energy’s financial condition and results from operations. In connection with the NMGC acquisition, TECO Energy recorded additional goodwill and long-lived assets that could become impaired.

TECO Energy has substantial indebtedness, which could adversely affect its financial condition and financial flexibility.

TECO Energy has substantial indebtedness, which has resulted in fixed charges it is obligated to pay. The level of TECO Energy’s indebtedness and restrictive covenants contained in its debt obligations could limit its ability to obtain additional financing.

TECO Energy, TECO Finance, TEC, NMGC and NMGI must meet certain financial covenants as defined in the applicable agreements to borrow under their respective credit facilities. Also, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments.

Although TECO Energy was in compliance with all required financial covenants as of Sept. 30, 2015, it cannot assure compliance with these financial covenants in the future. TECO Energy’s failure to comply with any of these covenants or to meet its payment obligations could result in an event of default which, if not cured or waived, could result in the acceleration of other outstanding debt obligations. TECO Energy may not have sufficient working capital or liquidity to satisfy its debt obligations in the event of an acceleration of all or a portion of its outstanding obligations.

TECO Energy also incurs obligations in connection with the operations of its subsidiaries and affiliates that do not appear on its balance sheet.

Financial market conditions could limit TECO Energy’s access to capital and increase TECO Energy’s costs of borrowing or refinancing, or have other adverse effects on its results.

TECO Finance and TEC have debt maturing in 2016 and subsequent years, which may need to be refinanced. Future financial market conditions could limit TECO Energy’s ability to raise the capital it needs and could increase its interest costs, which could reduce earnings. If TECO Energy is not able to issue new debt, or TECO Energy issues debt at interest rates higher than expected, its financial results or condition could be adversely affected.

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TECO Energy enters into derivative transactions, primarily with financial institutions as counterparties. Financial market turmoil could lead to a sudden decline in credit quality among these counterparties, which could make in-the-money positions uncollectable.

TECO Energy enters into derivative transactions with counterparties, most of which are financial institutions, to hedge its exposure to commodity price and interest rate changes. Although TECO Energy believes it has appropriate credit policies in place to manage the non-performance risk associated with these transactions, turmoil in the financial markets could lead to a sudden decline in credit quality among these counterparties. If such a decline occurs for a counterparty with which TECO Energy has an in-the-money position, TECO Energy could be unable to collect from such counterparty.

Declines in the financial markets or in interest rates used to determine benefit obligations could increase TECO Energy’s pension expense or the required cash contributions to maintain required levels of funding for its plan.

Under calculation requirements of the Pension Protection Act, as of the Jan. 1, 2015, measurement date, TECO Energy’s pension plan was essentially fully funded. Under MAP 21, TECO Energy is not required to make additional cash contributions over the next five years; however TECO Energy may make additional cash contributions from time to time. Any future declines in the financial markets or further declines in interest rates could increase the amount of contributions required to fund its pension plan in the future, and could cause pension expense to increase.

TECO Energy’s financial condition and results could be adversely affected if its capital expenditures are greater than forecast.

In 2015, TECO Energy is forecasting capital expenditures at Tampa Electric to support the current levels of customer growth, to comply with the design changes mandated by the FPSC to harden transmission and distribution facilities against hurricane damage, to maintain transmission and distribution system reliability, to maintain coal-fired generating unit reliability and efficiency, and to add generating capacity at the Polk Power Station. TECO Energy was forecasting capital expenditures at PGS to support customer growth, system reliability, conversion of customers from other fuels to natural gas and to replace bare steel and cast iron pipe. Forecasted capital expenditures at NMGC is expected to support customer and system reliability and expansion.

If TECO Energy’s capital expenditures exceed the forecasted levels, it may need to draw on credit facilities or access the capital markets on unfavorable terms. TECO Energy cannot be sure that it will be able to obtain additional financing, in which case its financial position could be adversely affected.

TECO Energy’s financial condition and ability to access capital may be materially adversely affected by multiple ratings downgrades to below investment grade and TECO Energy cannot be assured of any rating improvements in the future.

TECO Energy’s senior unsecured debt is rated as investment grade by S&P at ‘BBB’, by Moody’s at ‘Baa1’, and by Fitch at ‘BBB’. The senior unsecured debt of TEC is rated by S&P at ‘BBB+’, by Moody’s at ‘A2’ and by Fitch at ‘A-’. The senior unsecured debt of NMGC is rated by S&P at BBB+. A downgrade to below investment grade by the rating agencies, which would require a two-notch downgrade by S&P and Fitch, and a three-notch downgrade by Moody’s, may affect TECO Energy’s ability to borrow, may change requirements for future collateral or margin postings, and may increase financing costs, which may decrease earnings. TECO Energy may also experience greater interest expense than it would have otherwise if, in future periods, it replaces maturing debt with new debt bearing higher interest rates due to any such downgrades. In addition, downgrades could adversely affect TECO Energy’s relationships with customers and counterparties.

At current ratings, TEC and NMGC are able to purchase electricity and gas without providing collateral. If the ratings of TEC or NMGC decline to below investment grade, Tampa Electric, PGS or NMGC, as applicable, could be required to post collateral to support their purchases of electricity and gas.

TECO Energy is a holding company with no business operations of its own and depends on cash flow from its subsidiaries to meet its obligations.

TECO Energy is a holding company with no business operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of TECO Energy’s operations are conducted by its subsidiaries. As a holding company, TECO Energy requires dividends and other payments from its subsidiaries to meet its cash requirements. If TECO Energy’s subsidiaries are unable to pay it dividends or make other cash payments to it, TECO Energy may be unable to pay dividends or satisfy its obligations.

In the third quarter of 2014 TECO Coal was classified as an asset held for sale, and its operating results have been reported as discontinued operations since that time. In addition, through June 30, 2015, TECO Energy has recorded non-cash valuation adjustments of approximately $128 million, after tax, to the carrying value of TECO Coal, and expects that any final closing adjustments will not be material. Upon closing of the sale on Sept. 21, 2015, TECO Coal recorded a previously disclosed charge in discontinued operations of $7.7 million, after-tax, related to black lung liabilities.

 

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The following table shows the number of shares of TECO Energy common stock deemed to have been repurchased by TECO Energy:

 

 

During the time that it was a TECO Energy subsidiary, TECO Coal was subject to regulation by the Federal MSHA under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this quarterly report.

 

Exhibits - See index on page 69.

 

 

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

 

 

 

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INDEX TO EXHIBITS

 

 

 

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